A Novel Experimental Setup to Analyze Model Thin Films Representing Cores for an Ultrasonic Radiation Study of Petroleum Reservoirs

An apparatus was developed for a visual representation of conventional core flooding tests using a Model Thin Film (MTF) setup. The configuration was intended to provide direct visual representation of a flooding process. For our purposes, we investigated asphaltene deposition on a thin-film core sample, by evaluating the oil recovery before and after subjecting rock samples to a sonication process to remove asphaltene deposits, part of an ongoing project. The process involved saturating a specific volume of core sample with an asphaltic crude oil sample and recording flow pressures throughout the process. In order to have a full grade asphaltene deposition on the core sample, an alkane reagent, heptane, was used as a solvent to subsequently flood the rock system. After the formation of the skin and asphaltic sediments, we conducted an oil flood and monitored flow pressures, higher inlet pressures confirmed plugging and asphaltic deposition in the rock matrix. The model thin film setup proved to be a very good demonstrational and experimental apparatus, as it provided excellent visual information relating to the oil flood, and allowed routine experimental pressure, temperature and flow readings to be taken. The prospect of obtaining accurate experimental results from the model thin film is bright. This apparatus is designed to be used for the ultrasonic radiation study of petroleum reservoirs

Experimental Investigation of Permeability and Fluid Loss Properties of Water Based Mud under High Temperature-High Pressure Conditions

Drilling in deeper formations and in high pressure and high temperature (HPHT) environments is a new frontier for the oil industry. Fifty years ago, no one would have imagined drilling in more than 10,000 feet of water depth like we do today. However, more issues need to be researched, tested, and studied in order to maintain a good drilling efficiency as deeper depths are drilled. One of these issues is the great effect that drilling at HPHT conditions has on the behavior of drilling fluids.The goal of this research was to study fluid loss properties of water based mud and its effect on permeability under HPHT dynamic conditions utilizing advanced laboratory equipment that allows for wide ranges of pressure and temperature. Filtration tests were performed at both ambient and HPHT conditions. After several laboratory evaluations of fluid loss additives available in the market, Polysal HT was found to be the most effective in reducing the fluid loss of the water based mud for both static and dynamic tests at HPHT conditions. It is economically designed to be saturated in salt and other brine system. An additive that encapsulates particles with protective polymer coating as colloid. Drilling fluid stabilizer especially in drilling hydratable shale and a remarkable effectiveness in wide range make up water (high saline and high hardness). The fluid loss behavior of the mud and the characteristics of the filter cake produced are the basic factors that need to be considered when determining mud treatment.A detailed workflow of experiments using equipment from OFITE HPHT Fluid Apparatus with differential pressure of 500 psi under 230°F with 2.5” filter paper (30 minutes) as well as OFITE Permeable Plugging Tester with 1,200 psi differential pressure @ 230°F using a ceramic disc were conducted. Also tests were conducted using the Low Temperature- Low Pressure API Filter Press at 100 psi @77°F with 3.5” filter paper for the purpose of comparison. Key words: Permeability; Fluid loss; Water based mud; High pressure high temperatur

Experimental Investigation of Permeability and Fluid Loss Properties of Water Based Mud Under High Pressure-High Temperature Conditions

ABSTRACT Drilling in deeper formations and in high pressure and high temperature (HPHT) environments is a new frontier for the oil industry. Fifty years ago, no one would have imagined drilling in more than 10,000 feet of water depth like we do today. However, more issues need to be researched, tested, and studied in order to maintain a good drilling efficiency as deeper depths are drilled. One of these issues is the great effect that drilling at HPHT conditions has on the behavior of drilling fluids. The goal of this research was to study fluid loss properties of water based mud and its effect on permeability under HPHT dynamic conditions utilizing advanced laboratory equipment that allows for wide ranges of pressure and temperature. Filtration tests were performed at both ambient and HPHT conditions. After several laboratory evaluations of fluid loss additives available in the market, Polysal HT was found to be the most effective in reducing the fluid loss of the water based mud for both static and dynamic tests at HPHT conditions. It is economically designed to be saturated in salt and other brine system. An additive that encapsulates particles with protective polymer coating as colloid. Drilling fluid stabilizer especially in drilling hydratable shale and a remarkable effectiveness in wide range make up water (high saline and high hardness). The fluid loss behavior of the mud and the characteristics of the filter cake produced are the basic factors that need to be considered when determining mud treatment. A detailed workflow of experiments using equipment from OFITE HPHT Fluid Apparatus with differential pressure of 500 psi under 230°F with 2.5" filter paper (30 minutes) as well as OFITE Permeable Plugging Tester with 1,200 psi differential pressure @ 230°F using a ceramic disc were conducted. Also tests were conducted using the Low Temperature-Low Pressure API Filter Press at 100 psi @77°F with 3.5" filter paper for the purpose of comparison

Experimental evaluation of corrosion inhibitors for completion fluids in the petroleum production systems

Abstract Corrosion is the natural and continuous degradation of materials caused by either chemical, mechanical, or electrochemical reactions. Corrosion inhibitors may be added to the completion fluids to address corrosion problems efficiently. It is critical to add corrosion inhibitors in completion fluids, specifically under high-temperature conditions, since the corrosion rate is higher when the temperature is high. This corrosion process limits the life of the drill tools or the oil and gas well and causes formation damage. This research studied corrosion and corrosion inhibition treatments for five completion fluids, namely potassium chloride, sodium chloride, sodium bromide, calcium chloride, and calcium bromide. Phosphate and sulfite-based corrosion inhibitors were individually added to the completion fluids, and their corrosion properties were studied to tackle the corrosion issue. In addition, a mixture of phosphate-based and sulfite-based corrosion inhibitors in completion fluids was studied. Additionally, the experimental results recommend using divalent brines as they were identified as a better medium for lowering corrosion rate and conditions than the monovalent brines. A novel aspect of this study is that the materials leveraged for conducting experiments are also used in actual petroleum production field operations. The experiments demonstrate that the corrosion rate can be efficiently controlled at high temperatures in deeper wells

Evaluation of the viability of nanoparticles in drilling fluids as additive for fluid loss and wellbore stability

Wellbore instability is an issue that, if left untreated, can cause wells to collapse, resulting in human, environmental, equipment, and revenue losses. Drilling fluids have been used to enhance the drilling process by lubricating and cooling the drill bit, eliminating cuttings, and most importantly, by improving the stability of the well by preventing fluid loss. However, there has been an increase in operational demands and challenges that call for drilling fluids to be more effective, economical, sustainable, and environmentally friendly. With shales that have infinitesimally small pores, nanoparticle additives in drilling fluids can be crucial in providing the properties that are necessary to prevent fluid loss and provide wellbore stability while meeting the operational demands of the present day. Therefore, this paper examines the use of nanoparticle additives including copper (II) oxide (CuO), magnesium oxide (MgO), and aluminum oxide (Al2O3) where they are tested under three conditions using the permeable plugging tester (PPT), high-temperature high-pressure (HTHP) fluid loss apparatus, and API low-temperature – low-pressure (LTLP) fluid loss apparatus under concentrations of 0.03% and 0.10%. Finally, based on the results, each nanoparticle sample (particle sizes between one and 100 nm) performed well in contributing to the aim of this project. CuO is the most effective inhibitor across all concentrations and under the three different conditions. It contributed to reducing the fluid loss from 37.6 mL to 18.2 and 13.2 mL, which is between 52% and 65% of fluid reduction. For MgO, it contributed to fluid loss reduction to 23.8 mL and 15 mL, which translated to 37%–60% of fluid loss reduction. The use of Al2O3 nanoparticles resulted in a fluid loss reduction to 33.6 mL and 17.8 mL, reducing the fluid loss up to 11%, at HTHP and up to 53% at LTLP. Unlike CuO and MgO, Al2O3 was less effective under HTHP conditions when compared to LTLP conditions. Al2O3 did not suffer as a significant diminishing benefit with increasing concentration in LTLP conditions however which means that at a higher concentration, it may begin to be more effective. Each material used in this study has its own specific and technical characteristics that will help create a progressive amount of property, such as providing stability and withstanding the high-temperature and high-pressure condition downhole